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COM/MP1/oma ALTERNATE DRAFT Agenda ID #10297
Alternate to Agenda ID #9932
Decision ALTERNATE PROPOSED DECISION OF PRESIDENT PEEVEY (Mailed 4/5/2011)
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
In the matter of the Application of PacifiCorp (U901E) for approval to implement a Net Surplus Compensation Rate.
(Filed March 1, 2010)
And Related Matters.
DECISION ADOPTING NET SURPLUS COMPENSATION
RATE PURSUANT TO ASSEMBLY BILL 920
DECISION ADOPTING NET SURPLUS COMPENSATION
RATE PURSUANT TO ASSEMBLY BILL 920
This decision fulfills the requirements of Assembly Bill (AB) 9201 and adopts a net surplus compensation (NSC) rate to compensate net energy metering customers for electricity they produce in excess of their on-site load at the end of a 12-month true-up period. Net energy metering customers who produce excess power over a 12-month period are known as "net surplus generators."
The decision finds that net surplus generation should, as a general principle, count toward the utilities' Renewables Portfolio Standard (RPS) targets, as stipulated by AB 920. Net surplus generation is exempt from two conditions normally required of RPS-eligible generation, namely RPS certification by the California Energy Commission and Western Renewable Energy Generation Information System metering and tracking requirements. However, the decision finds that net surplus generation should not apply to the utilities' RPS targets until the utilities confer with organizations involved in the voluntary Renewable Energy Credit (REC) market and devise a process to ensure that net surplus generation is not double counted in both the RPS program and the voluntary REC market. The decision establishes a deadline for the utilities to submit advice letters that include a common process for verifying the REC ownership status of net surplus generation.
The NSC rate will be calculated using the market price referent (MPR). Specifically, the rate will use the 20-year contract term rate for the earliest date listed in the rate table of the most recently adopted MPR. Using the 2009 MPR as an example, the rate is 9.67 cents per kilowatt-hour. Each utility shall adjust the MPR value using its time-of-delivery factors weighted by the generation profile of a typical fixed-axis solar panel. This adjustment increases the net surplus compensation rate by a range of 12 percent to 32 percent depending on each utility's specific time-of-delivery adjustment factor. Net surplus generators will not receive fixed payments over the lives of their generation facilities. Instead, whenever the MPR rate is updated, a new NSC rate will be calculated for all net surplus generators.
The net surplus compensation rate includes a value for the renewable attributes of the generation. On an interim basis, this embedded renewable attribute value shall be set by using the Western Electricity Coordinating Council-wide average renewable energy premium, published annually by the Department of Energy, which is currently listed as 1.83 cents per kilowatt-hour. Net surplus generators who do not transfer their renewable attributes to the utilities purchasing their excess generation will be compensated at the NSC energy-only rate, calculated as the difference of the time-of-delivery adjusted MPR and the renewable energy premium.
To expedite the initial NSC payments while the utilities and voluntary REC market organizations work to establish a REC ownership verification process, all net surplus generators will be paid at the energy-only rate. Once the REC ownership verification process has been approved by the Commission, net surplus generators may be compensated at the full NSC rate. The utilities should add retroactive payments for the renewable energy premiums not paid during the period before the Commission approves the REC ownership verification process to a subsequent NSC payment.
Assembly Bill (AB) 920 amends Pub. Util. Code § 28272 and requires the Commission to establish a program to compensate net energy metering (NEM) customers for electricity produced in excess of on-site load at the end of a 12-month true-up period. In enacting AB 920, the Legislature stated that an NEM program combined with net surplus compensation (NSC) is one way to encourage substantial private investment in renewable energy resources, stimulate in-state economic growth, and reduce demand for electricity during peak consumption periods. (Section 2827(a).)
Specifically, the statute directs the Commission to adopt an NSC valuation to compensate a net surplus customer-generator for surplus kilowatt-hours over 12 months. The statute states, in pertinent part, that:
The net surplus electricity compensation valuation shall be established so as to provide the net surplus
customer-generator just and reasonable compensation for the value of net surplus electricity, while leaving other ratepayers unaffected. The ratemaking authority shall determine whether the compensation will include, where appropriate justification exists, either or both of the following components:
(i) The value of the electricity itself.
(ii) The value of the renewable attributes of the electricity.
In establishing the rate pursuant to subparagraph (A), the ratemaking authority shall ensure that the rate does not result in a shifting of costs between solar customer-generators and other bundled service customers. (Section 2827 (h)(4)(A)and (B).)
Customers may opt to receive either a payment for net surplus generation (NSG) or to roll a credit for that generation into the next 12-month true-up period. (Section 2827(h)(3).) According to AB 920, the Commission shall establish an NSC rate by January 1, 2011.
In an Assigned Commissioner Ruling dated January 15, 2010,3 in Rulemaking 08-03-008 (January 15th ACR), President Peevey directed Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E), to file applications no later than March 1 proposing an NSC rate, as well as other program implementation details pursuant to AB 920. Small and multi-jurisdictional investor-owned electric utilities were invited but not required to file applications as well. The
January 15th ACR posed a series of questions regarding implementation of
AB 920 and asked the utilities to respond to those questions.
On March 1, PacifiCorp, d.b.a. Pacific Power (PacifiCorp) filed the above-captioned application to implement an NSC rate. Subsequently, on March 15, Sierra Pacific Power Company4 (Sierra Pacific), PG&E, SCE, and SDG&E, each filed their above-captioned applications to establish an NSC rate. The five applications were consolidated by Chief Administrative Law Judge (ALJ) Ruling on April 1 because the applications raise similar issue of law and fact.
Responses to the five utility applications were filed by Californians for Renewable Energy Inc. (CARE), the Commission's Division of Ratepayer Advocates (DRA), the Interstate Renewable Energy Council (IREC), PG&E, and jointly by the California Solar Energy Industries Association and the Environment California Research and Policy Center (together CALSEIA/EC). Protests to the applications were filed by the Acton Town Council (Acton), the City of San Diego, CARE,5 Donald W. Ricketts, and jointly by the Solar Alliance and Vote Solar Initiative (together Joint Solar Parties).
A prehearing conference (PHC) was held on May 18 to discuss the scope and schedule of this application, and a scoping memo was issued on June 1.
On June 21, non-utility parties filed their proposals for NSC rates. Proposals were filed by Acton, CALSEIA/EC, DRA, IREC, the Joint Solar Parties, and the City of San Diego. In addition, PG&E, PacifiCorp, SCE, SDG&E and Sierra Pacific filed supplemental information regarding their applications as directed in the scoping memo.
A workshop to discuss the proposals was held on July 9. Following the workshop, comments and reply comments on the proposals were filed by Acton, CALSEIA/EC, CARE, DRA, IREC, the Joint Solar Parties, PG&E, PacifiCorp, SCE, SDG&E, the City of San Diego, Sierra Pacific, Solutions for Utilities, The Utility Reform Network (TURN), and Wal-Mart Stores, Inc. (Walmart). A PHC scheduled for August 26 was cancelled by the assigned ALJ after she determined that further proceedings were unnecessary and that the case was submitted as of the reply comments on August 6, 2010.
3.1. Commission Authority to Set a Net Surplus Compensation Rate
3.1.1. Parties' Positions
The utilities raise the issue of whether the Commission has the authority to set an NSC rate given Federal Energy Regulatory Commission (FERC) jurisdiction over "the sale of electric energy at wholesale in interstate commerce."6 According to the utilities, when an NEM customer produces excess power but receives a bill credit, i.e., a credit against its retail purchases, FERC considers this "netting" to be a billing arrangement and not a wholesale sale. PG&E cites a 2004 FERC order that states:
...under most circumstances [FERC] does not exert jurisdiction over a net energy metering arrangement when the owner of the generator receives a credit against its retail power purchases from the selling utility. [Footnote omitted.] Only if the Generating Facility produces more energy than it needs and makes a net sale of energy to a utility over the applicable billing period would [FERC] assert jurisdiction. [Footnote omitted.]7
Thus, the utilities claim FERC does not assert pricing jurisdiction over NEM billing arrangements where there is no "net sale" of electricity. However, they contend that if a customer's generating facility produces more energy than it needs and makes a net sale of energy to a utility over the applicable billing period and receives direct compensation for excess electricity, i.e., a check or one time payment rather than a bill credit offsetting future purchases, FERC considers this net sale a FERC jurisdictional wholesale transaction. (PG&E, 3/15/10 at 33; SDG&E, 3/15/10 at 6; PacifiCorp 3/1/10 at 3.)
SDG&E further asserts that the only time a state commission has a role in setting a wholesale rate is under the Public Utility Regulatory Policies Act (PURPA),8 which establishes a separate framework applicable to qualifying facilities (QFs) and provides that the state adopted rate may not exceed avoided cost. (SDG&E, 3/15/10 at 5-6.) SDG&E notes that FERC recently confirmed this "avoided cost" requirement for state-set wholesale rates. (SDG&E, 7/23/10 at 4, citing 132 FERC ¶ 61, 047 (July 15, 2010).) Similarly, CARE, DRA, PacifiCorp, PG&E and TURN agree that recent FERC orders appear to preclude net surplus compensation unless it represents the utilities' avoided costs.
In contrast to these jurisdictional concerns, CALSEIA/EC, the City of San Diego, and IREC contend the state has the authority to set an NSC rate without restriction. CALSEIA/EC contend the question of Commission authority to set wholesale prices is irrelevant because "no seller is required to sell electricity to the utilities." (4/23 at 17.) Further, CALSEIA/EC assert that
AB 920 requires the utilities to offer to compensate for net surplus as an incentive to increase energy efficiency and meet solar rooftop environmental goals. IREC contends that NEM is a "billing arrangement" and not a wholesale sale. Likewise, the City of San Diego considers the utilities' argument that NEM customer-generators must obtain certification as QFs as a creative barrier in order to pay NEM customers a lower rate for their net surplus generation. Both the City of San Diego and IREC note that wind and solar facilities with net power production capacity of 1 megawatt (MW) or less are no longer required to file a QF certification with FERC. (IREC, 4/23/10 at 11, fn. 26 citing FERC Order No. 732, 130 FERC ¶ 61,214 (March 19, 2010).)
In identifying the NSC rate to be paid to NEM customers, the Commission must consider both state and federal requirements. State law requires the Commission to establish a value for the NSC rate to be paid to NEM customers. Section 2827 requires that the NEM customer receive "just and reasonable compensation for the value of net surplus electricity, while leaving other ratepayers unaffected."9 Section 2827 also provides that "where appropriate justification exists" the NSC can include either or both of "[t]he value of the electricity itself" or the "value of the renewable attributes of the electricity."10 The statute then reiterates that in establishing the NSC the Commission shall ensure that it "does not result in a shifting of costs between solar
customer-generators and other bundled service customers."11
When we consider federal law, we find the utilities are correct that FERC has held that a net billing arrangement is not subject to FERC jurisdiction so long as no "net sale" is made to the utility.12 In addition, FERC has held that transfers of net surplus energy by a net metering customer to a utility are wholesale transactions that may comply with either the Federal Power Act (FPA) or PURPA.13
A recent FERC order reiterates the Commission has a wide degree of latitude in establishing avoided cost rates under PURPA and clarifies that the concept of a multi-tiered avoided cost rate structure is consistent with the avoided costs requirements of PURPA. (133 FERC ¶ 61,059 (October 21, 2010) at paras. 20 and 24.) As this FERC order explains, avoided cost rates under PURPA may "differentiate among [QFs] using various technologies on the basis of the supply characteristics of the different technologies." (Id. at para. 23.) The order further states that avoided cost rates for purchases from QF must be, among other things, at rates that are not in excess of the "the incremental cost to the electric utility of alternative electric energy" which is further defined as "the cost to the electric utility of the electric energy which, but for the purchase from [the QF], such utility would generate or purchase from another source." (Id. at ¶ 22.)
Thus, the Commission should implement the NEM Program pursuant to PURPA. Under such a program, the Commission should establish an NSC rate that does not exceed the utility's full avoided costs, but the Commission may differentiate an avoided cost rate for net surplus generators from the avoided costs rates currently paid to QFs.
NEM customers eligible for NSC under AB 920 must use a solar or wind generation facility of not more than 1 MW. FERC has recently modified its regulations so that generating facilities of 1 MW or less no longer need to file a certification of QF status with FERC to be considered a QF. (FERC Order 732, 130 FERC ¶ 61, 214 (March 19, 2010) and 18 CFR § 292.203(d).) Accordingly, NEM customers can be considered QFs exempt from certification requirements at FERC and may receive net surplus compensation at a rate that does not exceed avoided costs, as determined by the Commission. As discussed further in the next section, for purposes of interconnection, the Commission would require each NEM to notify the utility that they are a QF exempt from certification filing. This notification should occur at the time the NEM customer affirmatively elects either an NSC payment or application of their net surplus to future usage, pursuant to Section 2827(h)(3) and can be easily accomplished by the utility creating a notification form that customers would sign when making their NSC payment election.
3.2. Authority over Interconnection
3.2.1. Parties' Positions
In addition to concerns over Commission authority to set the NSC rate, PG&E raises jurisdictional concerns regarding interconnection issues. PG&E is concerned that because FERC will consider payment for net surplus a wholesale sale, FERC will assert jurisdiction over the interconnection between an NEM customer and PG&E. PG&E is concerned that application of FERC interconnection rules to NEM projects could result in customers paying higher interconnection application fees ($500 to $1000), and subject them to costs for interconnection studies and distribution system modifications. (PG&E, 3/15/10 at 32-35 and 6/21/10 at 7.)
PG&E proposes three possible solutions to its jurisdictional concerns. It suggests the Commission: 1) file a petition asking FERC to disclaim jurisdiction over interconnection of NEM customers electing compensation for net surplus generation under AB 920; 2) require all NEM customers to be QFs as a condition for eligibility for NSC (and thereby able to use the Commission's Rule 21 interconnection procedures); or 3) ask FERC to approve changes to the
FERC-filed wholesale distribution tariff so that the FERC jurisdictional interconnection rules are the same for NEM customers electing NSC as the rules for those not electing NSC. PG&E prefers the first option, a petition asking FERC to disclaim jurisdiction.
The City of San Diego agrees with PG&E that the Commission should ask FERC to disclaim jurisdiction. Joint Solar Parties, IREC, and CALSEIA/EC disagree with PG&E. They maintain that FERC interconnection rules do not impact NSC implementation and the Commission has clear jurisdiction over interconnection arrangements for NEM customers.
We share PG&E's preference for Rule 21 to govern interconnections of customers who receive NSC. We prefer PG&E's second option and therefore, we will require NEM customers opting for an NSC payment to self-designate as QFs, which will entitle NEM customers to interconnect pursuant to the Rule 21 process.
Now that we have clarified our authority to identify an NSC rate based on avoided costs under PURPA, we turn to the various proposals offered by the parties.
AB 920 requires the Commission, when implementing the net surplus compensation rate, to consider whether the rate should include both the value of the electricity and the value of the renewable attributes of the electricity. The five utility proposals are similar in that each utility recommends a net surplus compensation rate that reflects a value of electricity based on the costs avoided by the utility for purchases of electricity. Most of the utilities then suggest an adder for the value of the renewable attributes of the power produced by eligible NEM customer-generators, i.e., generators using either a solar or wind turbine electric generating facility, or a hybrid system of both. (Section 2827(b)(4).) The actual basis for the electricity and renewable attribute values varies by utility. All five utilities generally argue that other ratepayers will be unaffected by an NSC rate as long as it is set equivalent to the costs the utility avoids by not generating energy itself.
The other, non-utility parties generally propose higher NSC rates, arguing that net surplus generation should be compared to the price of other renewable power sources. We describe the various proposals in greater detail below.
4.1. PG&E's Proposal
PG&E asserts that the NSC rate should be set equal to the cost the utility avoids by purchasing one less kilowatt hour (kWh) of energy from the California Independent System Operator (CAISO). Therefore, PG&E's proposed NSC rate is based on a simple average of hourly day-ahead locational marginal prices of electricity at the utility's default load aggregation point (DLAP). This simple average would be based on DLAP prices between the hours of 7 a.m. and 5 p.m., or the hours of daylight when NEM customers generally produce power, over the 12-month true-up period. PG&E calculates that for December 2009, this average DLAP price was 5 cents/kWh and that from April to December 2009, the average DLAP price was 3.9 cents/kWh. (PG&E, 3/15/10, Attachment B at 4; PG&E, 6/21/10, Appendix A at 3.) PG&E states that use of an established, fully accessible price as the basis for NSC would reduce utility implementation costs.
To compensate for renewable attributes, PG&E would then add to the DLAP price the average renewable energy credit (REC) price over a 12-month period representing the cost PG&E avoids purchasing the same amount of renewable kWhs. Because RECs are not yet traded and there is no public REC price available, PG&E proposes that in the interim until REC market prices are publicly available, the net surplus compensation for all payments in a calendar year should be based on PG&E's system average generation rate in effect on January 1 of that year. PG&E states that although this is an embedded, or average cost, as opposed to an avoided cost, it includes both the value of electricity and the value of renewable attributes. Currently for 2010, PG&E's system average generation rate is 8.1 cents/kWh. (PG&E, 3/15/10 at 5.)
4.2. SCE's Proposal
SCE contends that because the Commission must identify a just and reasonable rate that does not shifts costs between customer-generators and other customers, the net surplus compensation rate should be based on a market metric. (SCE Testimony, 3/15/10 at 3.) SCE proposes to use a cost figure derived from the Market Redesign and Technology Upgrade (MRTU) Integrated Forward Market (IFM) as a reasonable proxy for a transparent market price for electricity that SCE would otherwise pay to procure electricity. Specifically, SCE would base its rate on the average of hourly MRTU-IFM South of Path 15 Generation Hub prices over a year, weighted using SCE's 2009 load profile for residential customers. (SCE, 6/21/10, Attachment A at A-1.) For the period
May 2009 to April 2010, this price is 3.793 cents/kWh. (Id. at A-2.) SCE would then add to this a value for renewable attributes based on renewable premiums for the Western Electricity Coordinating Council (WECC), as published periodically by the United States Department of Energy (DOE). SCE states that the average premium reported for the WECC is 1.83 cents/kWh (Id.)
SCE proposes that the ultimate NSC a customer would receive would be based on "discounting" any bill credit remaining at the conclusion of the relevant period. Under SCE's proposal, a customer must have a bill credit to receive NSC. SCE would use the bill credit to calculate a "payout percentage" by adding together a class weighted average MRTU price for the applicable period and the average premium for renewable energy in the WECC, and dividing that sum by the average retail price for the individual NEM customer's rate group. A customer's NEM bill credit remaining at the end of the period would be multiplied by the payout percentage to determine net surplus compensation to the customer. SCE would calculate the net surplus compensation payout percentage monthly for each rate group. (See Exh. SCE-1, 3/15/10 at 8.)
According to SCE, use of a market-based NSC rate such as the one it proposes ensures that non-participating customers are not impacted because the payment for net surplus reflects what SCE would otherwise pay in the market. In addition, SCE contends that its proposal minimizes the administrative costs of the NSC program, and therefore has a minimal effect on non-participating customers.
4.3. SDG&E's Proposal
SDG&E proposes a net surplus rate based on the 12-month rolling average of short run avoided cost (SRAC) energy rates paid to QFs. The rolling average would correspond to the NEM customer's 12-month true-up period. According to SDG&E, over the last five years, the 12-month rolling average for the
non-time-of-use SRAC energy rate has ranged from 4.5 cents/kWh to 9.3 cents/kWh. (SDG&E, Davidson Testimony, 6/18/10 at LCD-6.)
SDG&E's proposal includes a method to account for the time of delivery of the net surplus. For commercial and industrial NEM customers with time-of-use (TOU) metering, surplus kWhs would be aggregated by the TOU period and paid based on the SRAC energy rate for each period. For all other NEM customers, NSC would be calculated using the non-TOU SRAC rate, adjusted for time of delivery using a representative profile of excess generation derived from SDG&E load research data from residential NEM customers. (SDG&E, 7/23/10 at 5.) SDG&E proposes an annual update of this adjustment factor based on changes to both the SRAC TOU factors and the representative load profile. According to SDG&E, since the NEM program is a tariff with no long-term commitment from the customer, payments for excess generation should be at SRAC.
In addition, SDG&E would compensate for renewable attributes by adding the Market Price Referent (MPR) greenhouse gas (GHG) adder, or 0.8 cents/kWh, to the net surplus compensation rate until a REC market in California can be relied upon to provide public information on a competitive REC price. (SDG&E, Davidson Testimony, 6/18/10 at LCD-11.) According to SDG&E, its NSC rate is transparent, has low administrative costs, complies with AB 920's mandate to not shift costs to bundled ratepayers, and meets FERC's avoided cost requirements.
4.4. PacifiCorp's Proposal
PacifiCorp proposes an NSC rate based on the QF avoided cost rates approved in its Oregon service territory, which are currently set at $.0512 per kWh for on-peak power and $.0395 per kWh for off-peak power. (PacifiCorp, 6/21/10 at 3.) A weighted average of these two rates based on the typical annual split of on-peak and off-peak hours results in a rate of $.0462 per kWh. (Id.) PacifiCorp also proposes an adder for environmental attributes and transmission and distribution system benefits of $.01 per kWh. According to PacifiCorp, only 34 customers take NEM service in its California territory and none of these customers has ever had net surplus generation at the end of the 12-month cycle.
4.5. Sierra Pacific's Proposal
Sierra Pacific has 20 NEM customers and only two had a net surplus in 2009. Given this low NEM participation, Sierra maintains that its circumstances warrant the use of a simplified approach. Sierra Pacific proposes to use the generation component for baseline quantities from its otherwise applicable retail rates as a proxy for the avoided cost of energy. According to Sierra Pacific, this generation component is currently equal to $.05745 per kWh. (Sierra Pacific, 6/21/10 at 3.) Sierra Pacific does not propose paying for renewable attributes of the electricity because customer generators are not currently eligible for the Renewable Portfolio Standard (RPS) program and most NEM customer generation is not tracked by the Western Renewable Energy Generation Information System (WREGIS). Sierra Pacific contends that absent revisions to the California Energy Commission's (CEC's) RPS Eligibility Guidebook, generation from NEM customers has no RPS value and it would be inappropriate to include a renewable adder in the NSC rate.
4.6. Responses to Utility Proposals
In response to the utility NSC proposals, most parties agree that the Commission should adopt a consistent methodology to set the NSC rate for all the utilities, but actual rates may vary by utility based on utility-specific cost data. Parties also generally agree that the Commission should minimize the administrative costs of implementing the NSC rate to avoid burdening non-participating customers.
Only two parties support a utility NSC rate proposal. CARE supports SDG&E's proposal to use SRAC energy rates as the basis for NSC, as well as PacifiCorp's proposal to compensate based on Oregon QF avoided costs prices. Wal-Mart supports SDG&E's proposal to use Commission-approved SRAC rates as the basis for NSC.
The remainder of the parties generally opposes the utility NSC proposals.
According to the Joint Solar Parties, CALSEIA/EC, City of San Diego, and Acton, the utilities' proposals to use either short-term wholesale market prices, SRAC rates, or average generation rates do not reflect the costs the utilities would incur to procure a similar quantity of renewable generation to meet RPS requirements. CALSEIA/EC maintain that NSC payments based on average energy rates do not reflect that most NEM solar systems provide excess generation during peak periods of electricity demand. Thus, these parties contend that the utilities' proposals substantially under compensate customer generators for the value of on-peak, RPS eligible energy and fail to encourage surplus generation as envisioned in AB 920. Further, the Joint Solar Parties claim the utilities' proposals do not include any compensation for avoided capacity costs.
4.7. Joint Solar Parties
The Joint Solar Parties agree with the utilities in concept that the NSC rate should be based on avoided costs. In their view, however, the proper avoided cost should be the Commission-adopted MPR, which is the all-in cost of a new 500 MW central station combined-cycle plant built in California, and includes costs to mitigate the plant's GHG emissions. They contend that the MPR is the correct avoided cost to use since it represents the "brown power" resource that the utility avoids constructing by instead purchasing and receiving RPS credit for net surplus generation. The Joint Solar Parties assert that because utilities will get RPS credit for net surplus purchases, they will avoid the long term costs of purchasing renewable generation under the RPS program and the value of renewable attributes is captured by the GHG mitigation costs incorporated into the MPR. In the future, however, they suggest a market-based REC price could be substituted for this GHG adder.
The Joint Solar Parties propose adjusting MPR to reflect the time of delivery (TOD) of solar generation, plus an adjustment for avoided line losses and avoided transmission and distribution (T&D) costs. According to the Joint Solar Parties, surplus power from NEM customer-generators typically serves nearby loads and reduces the loadings of both the local distribution feeder and the higher-voltage transmission and distribution grid, thus avoiding line losses. Plus, they assert that collectively, surplus generation from a large number of NEM customers can avoid the need for additional T&D capacity.
Specifically, the Joint Solar Parties propose the following adjustments to the MPR to set a NSC rate:
NSC = MPR x TOD factor + avoided line losses + avoided T&D
The Joint Solar Parties' TOD factor is calculated by applying a representative hourly solar output profile to the TOD factors used in the utility's most recent RPS solicitation. Joint Solar Parties explain that this TOD factor implicitly assumes that net surplus generation has the same distribution as the typical solar output profile, and is a reasonable simplifying assumption. They recommend a single solar production profile for each utility. Avoided line losses and avoided T&D would be based on the Commission's most recently adopted avoided cost model for energy efficiency (the "E3 avoided cost model").14
Joint Solar Parties recommend that the MPR rate that should apply for an individual NEM customer-generator is the 20-year contract rate beginning in the year that the NEM customer begins operation, and the rate would be fixed for the life of the NEM system. The Joint Solar Parties assert this would provide the customer certainty and would provide ratepayers a hedge against future increases in the price of fossil fuels. Existing NEM generators who went into operation prior to the MPR taking effect in December 2009, would receive a rate based on the 2008 MPR for a 20 year contract starting in 2009. The Joint Solar Parties propose the NSC rate could be updated by advice letter each time the Commission revises the MPR.
The Joint Solar Parties provide estimates for their proposed NSC, which vary depending on the utility. For a project that begins operation in 2009 or earlier, rates would begin with the 2008 MPR of 11.1 cents/kWh, and then be adjusted by TOD factors, avoided line losses, and avoided T&D costs using values distinct for each utility. Projects that begin in 2010 would be based on the 2009 MPR of 9.67 cents/kWh, also adjusted for TOD factors, and avoided line losses and T&D costs. Given all these adjustments, the Joint Solar Parties proposed rates are as follows:
Table 1: Joint Solar Parties' Proposed NSC Rates in cents/kWh15
NSC Rate for Projects that begin in 2009 or earlier
NSC Rate for Projects that begin In 2010
The Joint Solar Parties contend their proposed NSC is reasonable and will leave ratepayers unaffected because it reflects costs the utility will avoid through purchase of this generation. They maintain that an NSC rate based on MPR is appropriate because it includes payment for the value of capacity similar to the Commission's finding in D.82-01-103 that avoided cost rates should consider the value of energy and capacity from QFs. According to the Joint Solar Parties, the Commission already uses MPR to price surplus output from small renewable generations up to 1.5 MW pursuant to AB 1969,16 which is a program analogous to NSC. They contend that even if RPS legislation ends the use of the MPR for the RPS program, the Commission can maintain the MPR as an important pricing benchmark.
The utilities and TURN oppose the Joint Solar Parties' proposal to base NSC on the MPR. Acton supports use of the MPR, with suggested modifications. The details of the opposition to MPR are discussed below in Section 5.
CALSEIA/EC assert that the NSC rate should be based on the full value of peak-generated renewable electricity because it is essential to give NEM customers an adequate incentive to reduce their electricity consumption and avoid sending power to the grid without compensation. They claim that under the current NEM program, homeowners with solar installations have an incentive to waste electricity rather than give it away for free to their utility company. Therefore, they suggest the NSC be set at either of the following: 1) the full retail electric rate, or 2) the feed-in tariff rate for solar power systems that the Commission will determine when it implements Senate Bill (SB) 3217 in Rulemaking (R.) 08-08-009. CALSEIA/EC argue that when the Commission sets a feed-in tariff rate in R.08-08-009, that rate should include social and environmental benefits of solar as well as the electricity value.
CALSEIA/EC recommend that to calculate the NSC rate, the Commission should rely on a study they commissioned as part of the SB 32 feed-in tariff proceeding, which recommends a rate based on the MPR plus environmental and health benefits, time of delivery factors, avoided T&D and line losses, grid reliability, and REC values. They assert that the market value of a REC does not by itself represent the total value of renewable attributes. Therefore, they contend the Commission should consider environmental adders on top of the value of the REC in the NSC rate. Moreover, they suggest the NSC rate should be fixed for a ten-year period beginning with the date of online generation. CALSEIA/EC contend other ratepayers will be unaffected by their NSC rate proposal because few customers will be eligible for NSC. Thus, there will be minimal program cost to non-participants.
The CALSEIA/EC proposal is opposed by PG&E, PacifiCorp, TURN, and Acton, as discussed more fully in Section 6.1.2 below.
DRA proposes an interim rate to take effect on January 1, 2011, based on the most current MPR, adjusted based on time of delivery of the net surplus. SDG&E opposes DRA's interim MPR proposal, claiming it is not a proper avoided cost measure. Several parties oppose DRA's interim rate proposal, stating the Commission should simply adopt a final and permanent NSC rate at this time.
For a permanent NSC rate, DRA proposes the Commission set the NSC based on the distributed generation (DG) avoided cost methodology recently adopted in D.09-08-026 and used in the NEM cost-effectiveness evaluation performed in accordance with that decision. DRA notes that DG avoided costs have not been subject to public input, so additional public input is needed before they could be used to set NSC rates. Furthermore, DRA suggests that the NSC be adjusted for each customer's net generation profile. DRA contends this would require only simple arithmetic calculations involving TOU data for each customer which DRA asserts should be readily available in the utility billing system. Several parties oppose this proposal, stating it would be too difficult and costly to implement.
4.10. City of San Diego
The City of San Diego is a large customer of SDG&E with an active Distributed Energy Resources Program involving over 18 MW of generating capacity. The City contends that ideally the NSC rate should be set at the utility's marginal cost for renewable generation. However, since this price is not publicly available, a reasonable proxy is the cost of utility-owned renewable energy facilities, such as the all-in average cost of power from the utilities' own photovoltaic (PV) generating facilities. The City of San Diego estimates this rate is 20 to 25 cents per kWh. In the alternative, the City proposes the NSC be set equal to the utility's full retail electric rate.
The City of San Diego asserts this is reasonable because most generation from NEM customers comes from PV, and although this power is intermittent, the Commission has previously paid QFs for capacity. It maintains that a large collection of NEM customers can provide a quantity of energy that is as predictable as power provided by utility-owned solar projects. The City of San Diego asserts its proposed NSC rate leaves other ratepayers unaffected since it displaces purchases of renewable power at the utilities' marginal cost.
The utilities and TURN oppose the City of San Diego's proposal.
According to Acton, the NSC should be based on the renewable energy prices defined in executed RPS contracts approved by the Commission. Specifically, the NSC rate should reflect RPS contract rates during the same
true-up interval because the surplus generation is new renewable energy that the utilities can count toward their RPS goals, and it avoids purchases of renewable energy. Using RPS contract values will leave other ratepayers unaffected as they will pay the same for all renewable power. Customer generators should be paid for the actual value of their surplus energy and the best measure of this is actual contract prices, not short-term market prices as the utilities propose. Furthermore, Acton proposes that the NSC should be based on the time of delivery, i.e. the time the excess power is placed on the distribution network, relying on existing rate data.
IREC does not offer a specific rate proposal, but urges a single methodology where the precise rate can vary across utilities. IREC contends that solar installations by NEM customers are fixed additions to the grid that will provide energy over multiple decades, as recognized in the Commission's
long-term procurement proceedings. Therefore, IREC supports the Joint Solar Parties' proposal to value excess energy at a long-run avoided cost using the MPR. Moreover, IREC asserts that to value surplus generation from NEM customer-generators at a short-run avoided cost price while valuing wholesale DG at a long-run MPR price creates an unexplained disconnect in the valuation of these similar resources.
4.13. Solutions for Utilities
Solutions for Utilities supports NSC based on a utility's retail electric rate, which it further maintains should be the Tier 3 summer rate because the utility company will avoid transmission and distribution expenses and it will essentially sell the excess power to adjacent property owners at tiered rates. Solutions for Utilities contends its proposal will incentivize surplus generation.
PG&E and SDG&E oppose this proposal, claiming that payment based on Tier 3 summer rates would be in excess of utility avoided costs.
CARE does not provide its own NSC rate proposal, but it supports the proposals by SDG&E and PacifiCorp. In addition, CARE contends that any excess energy produced is FERC jurisdictional, and since TOU meters can take readings in ten second intervals, the applicable NEM true-up period should be a ten second interval. It is unclear from CARE's comments how the Commission would implement a ten second true-up period given the existing NEM program with an annual true-up.18
We now address issues surrounding the renewable attributes of net surplus generation and the treatment of any RECs that may be created by NEM customers' generation facilities. AB 920 provides that the utilities that purchase net surplus generation shall receive the RECs associated with such generation and that the electricity purchased shall count toward their RPS targets. Specifically, Section 2827(h)(5) states:
(5)(A) Upon adoption of the net surplus electricity compensation rate by the [Commission], any renewable energy credit, as defined in Section 399.12, for net surplus electricity purchased by the electric utility shall belong to the electric utility. Any renewable energy credit associated with electricity generated by the eligible customer-generator that is utilized by the eligible customer-generator shall remain the property of the eligible
(B) Upon adoption of the net surplus electricity compensation rate by the [Commission], the net surplus electricity purchased by the electric utility shall count toward the electric utility's renewables portfolio standard annual procurement targets for the purposes of paragraph (1) of subdivision (b) of Section 399.15, ....
Section 399.12 defines a REC as "a certificate of proof, issued through the accounting system established by the [CEC] pursuant to Section 399.13, that one unit of electricity was generated and delivered by an eligible renewable energy resource." Section 399.13 confers upon the CEC the authority to certify eligible renewable energy resources, to design and implement an accounting system to verify compliance with RPS by retail sellers, to ensure electricity generated by renewable energy resources is only counted once, and to establish a system for tracking RECs. Currently, in order to qualify for RPS compliance, renewable energy generators must be certified as eligible by the CEC, and the REC must be tracked and verified in WREGIS, which requires the meter measuring the generation to have accuracy of plus or minus two percent. At this time, almost no customer-side DG is RPS-eligible, except DG systems under AB 1969 tariffs.19
Note that the paragraphs cited above do not appear to account for any circumstances where customer generators have transferred the rights to their RECs to a third party. This may occur either because the contract between the customer-generator and the developer specifies that the developer retains the right to all renewable attributes or because the customer-generator has retained the right to original ownership of the renewable attributes but sells them to another party in the voluntary REC market.
Broadly, there are three concerns about applying net surplus generation toward the utilities' RPS targets. First, without CEC certification and WREGIS registration, electricity cannot, with the exception noted above, count toward RPS compliance. We must determine whether the legislature intended a similar exception to apply to net surplus generation. Second, even if the legislature intended NSG to be exempt from the CEC certification and WREGIS registration requirements, some net surplus generators have sold off the rights to the renewable attributes associated with the electricity produced by their systems. In these cases, the administrative burden of verifying which net surplus generators have retained the rights to their renewable attributes may be large relative to the total value of net surplus generation. Without verification, the NSG produced by any given system that is counted for RPS compliance and also used in a voluntary REC program would be double counted and the integrity of the RPS program and voluntary REC markets would be compromised. Third, RECs are normally minted in one MWh units. Because NSG is trued-up over a twelve-month period, few net surplus generators are likely to produce NSG in exact MWh increments. This raises questions about how to deal with any quantities of NSG left at the end of the true up period once all MWh increments have been accounted for. Each of these three issues is discussed in more detail below.
5.1. CEC RPS Eligibility and WREGIS Requirements
Several parties, namely PG&E, SCE, the Joint Solar Parties, CALSEIA/EC, IREC, the City of San Diego and DRA, suggest that AB 920, in effect, exempts net surplus generation from Sections 399.12 and 399.13, which mandate CEC RPS eligibility and WREGIS metering and registration requirements. These parties contend that AB 920 expressly intends for the utilities to receive RPS credit from net surplus generation and count it toward their RPS annual procurement targets. They argue that CEC certification and WREGIS metering requirements are not necessary preconditions for this to occur. According to SCE, AB 920 should be construed in a simple fashion to facilitate utility purchases of renewable attributes from NEM customers. SCE recommends a "carve-out" arrangement, where net surplus generation purchased by the utilities under AB 920 would not have to be tracked in WREGIS or meet CEC RPS eligibility requirements in order to be counted towards utility RPS targets. Similarly, DRA argues:
To the extent two statutes are irreconcilable, when a subsequently enacted specific statute directly conflicts with an earlier more general provision, it is well settled that the subsequent legislation affects a limited repeal of the former statute.... [fn omitted] Thus, to the extent that the RPS statute (and subsequent regulations) required CEC certification and WREGIS tracking, those requirements do no [sic] apply to NEM excess generators under AB 920 because those requirements from the earlier enacted RPS statutes are deemed repealed. (DRA, 6/21/10, at 18, citing Governing Bd. v. Mann, 18 Cal. 3d 819, 829 (1977).)
Additionally, PG&E and others claim it would be complex and expensive for customers to obtain RPS certification and register with WREGIS. These parties contend the simple and cost-effective approach is to allow customers with net surplus generation to receive compensation for the renewable attributes of their excess generation, and for the utilities to get RPS credit for the generation, whether or not the facility is certified as RPS eligible by the CEC and whether or not the facility generates a REC that is tracked through WREGIS.
We agree with these parties' suggestion that the language of AB 920, enacted after Sections 399.12 and 399.13, plainly allows net surplus generation to count toward RPS procurement targets, and as a general principle, we will permit the utilities to do so. While we believe that the legislature intended to exempt net surplus generation from the CEC certification and WREGIS tracking requirements that would normally apply, we do not believe that the legislature intended to permit this outcome where it would undermine the integrity of REC markets. Issues concerning the tracking of renewable attributes associated with net surplus generation are discussed in the next section.
5.2. Renewable Attribute Tracking and Sales of RECs to Third Parties
In order to resolve whether net surplus generation should apply toward the utilities' RPS goals, we must ensure that the NSC program does not undermine the integrity of REC markets by allowing any net surplus generation to count toward the RPS targets while producing RECs claimed by another entity. This suggests that NEM customers need to certify that they own the RECs associated with their power in order for the utility to compensate the NEM customer for the RECs and count them towards RPS targets. PG&E contends that customers should not be required to prove REC ownership to receive compensation for net surplus generation. The remaining utilities, Acton, IREC, CALSEIA/EC, City of San Diego, and the Joint Solar Parties recommend that customers should only receive payment for renewable attributes if they affirm ownership of the REC. They suggest that if a customer has sold its RECs, the utility should be allowed to pay a lower, or "brown power price," for the net surplus generation without RECs.
Because the CEC does not currently certify behind-the-meter resources for RPS eligibility, any RECs produced by these facilities cannot be used for RPS compliance. However, RECs from behind-the-meter facilities may be accepted in the voluntary REC market. WREGIS allows facilities as small as 1 kW to register their output, and it also possible that some net surplus generators register their output in voluntary REC tracking systems that do not rely on WREGIS. However, the record of this proceeding does not provide any data to indicate which customer-generators in the IOUs' territories may be generating RECs in WREGIS or other REC tracking systems. Authorizing the utilities to apply net surplus generation toward their RPS targets without verification that the renewable attributes are not claimed by another party would undermine the integrity of voluntary REC markets.
The utilities have expressed concern about the administrative burden of requiring attestations from every net surplus generator. The Joint Solar Parties proposed that only net surplus generators with systems of 100 kW or greater be required to file an affidavit that they have not sold their RECs to another party. (Joint Solar Parties, 6/21/10 at 17.) PG&E agreed with the principle of setting a threshold but suggested setting the threshold at 500 kW. (PG&E, 7/23/10 at 15.) However, either of these approaches may result in the double counting of some net surplus generation RECs, which is, as PG&E states, "troubling." We share the utilities' concerns about the administrative burden of verifying REC ownership, but maintaining the integrity of REC markets, and the RPS program, is a paramount goal of the state's renewable energy policy. Thus, before authorizing the use of net surplus generation for RPS compliance, the utilities should reach out to organizations involved in the voluntary REC market, such as solar project developers, voluntary REC aggregators and voluntary REC certifiers to discuss possible methods of identifying the net surplus generators who have sold their RECs to another party. It may be more efficient to collect data on the net surplus generators who have sold the rights to their RECs from a relatively small number of voluntary REC market participants than from the net surplus generators themselves.
We instruct the utilities to initiate meetings with developers, aggregators, certifiers, and Energy Division staff. Based on these discussions the utilities should develop a common approach to ascertaining the REC ownership status of net surplus generators. The proposed approach should seek to create a list of the net surplus generators who do not own their RECs that is as complete as possible while taking into account the possible trade-off between completeness and administrative simplicity.
Within 120 days of the effective date of this decision, each investor-owned electric utility operation in California should file a Tier 3 advice letter that proposes a process for verifying the renewable energy credit ownership status of the net surplus generators in its territory and any revision to its net energy metering tariffs necessary to effect the proposed process. The proposed processes of PG&E, SCE, and SDG&E should be substantially the same. Due to the significantly smaller numbers of net surplus generators in their territories, the small and multi-jurisdictional investor-owned electric utilities may propose processes for verifying the renewable energy credit ownership status of the net surplus generators in their territories that differ from the process proposed by PG&E, SCE, and SDG&E.
Until the Commission approves a method for determining REC ownership, no net surplus shall count toward RPS targets. Any NSC-eligible net surplus generation that occurs before Commission approval of the REC ownership process may be carried forward to apply to RPS targets, provided that the RECs are also transferred to the purchasing utility.
REC ownership falls into one of four categories based on which entity (the customer-generator or the developer/installer) is the initial owner of the RECs and whether the generation from the net surplus generation facility is registered with a voluntary REC tracking service. Once the method for establishing REC ownership status is finalized, the net surplus generation of customer-generators who have retained the right to their RECs and who have not registered their systems with a voluntary REC tracking system will count toward RPS. Net surplus generation from facilities not registered with a voluntary REC tracking system whose RECs belong to the project developer (or other third party) should count toward RPS only if the developer certifies that none of the net surplus generation from the true-up period will be used to produce RECs at any time in the future. Net surplus generation from any facility that is registered with a REC tracking system will only count toward RPS targets if the REC owner transfers the RECs associated with the net surplus generation (that is, produced by the same facility during the true-up period) to the utility purchasing the net surplus generation.
SDG&E proposes that stakeholders should collaborate to develop a streamlined process for NEM customers to obtain RPS certification from the CEC and meet WREGIS accounting requirements. We agree that it would be preferable for the renewable attributes of customer-side DG to be tracked either in WREGIS or an alternative uniform tracking system for smaller facilities. The utilities and other parties should work with the CEC through its process for revising its RPS Eligibility Guidebook to have RPS certification and accounting requirements, including split ownership of RECs and aggregation, dealt with by the CEC and WREGIS.20 When a certification and tracking process for
customer-side DG is established, the net surplus generation should only count toward the RPS procurement targets if the RECs associated with that generation are also conveyed to the utility purchasing the net surplus generation.
5.3. Accounting for Partial RECs
According to Section 2827(h)(5)(A), any REC for net surplus electricity purchased by the electric utility shall belong to the electric utility, while any REC associated with electricity generated by the eligible customer-generator and used by the eligible customer-generator remains the property of the eligible
customer-generator. It is unclear whether WREGIS systems can track and otherwise account for RECs that would be split between the utility and the customer in such a fashion. In addition, RECs for RPS compliance are accounted for in 1 megawatt-hour (MWh) increments, and it is unclear if the utilities or another entity may aggregate the net surplus generation of multiple small NEM customers to create RECs in the appropriate 1 MWh increments. Because WREGIS (and presumably other REC tracking programs) denominate RECs in one MWh increments and RPS compliance is accounted for in one MWh increments, we will maintain a MWh as the basic unit of measurement for the RPS program. Consequently, the net surplus generation from any given facility above the last full MWh will not count toward the purchasing utility's RPS target for the year in which the true-up date occurs. However, the purchasing utility can bank the quantity that remains above the last full MWh of net surplus generation and roll it over to apply to the following year's net surplus generation from the same customer. The table below illustrates how this will apply to each net surplus generator's account.21
Application of Partial MWh of Net Surplus Credit toward RPS Targets
Current Year Net Surplus Generation (NSG), MWh
Banked NGS RPS Credit from Previous Year
NSG Credit Toward RPS Compliance in Current Year
NSG Banked from Current Year
According to the statute, the Commission may determine whether net surplus compensation should include either or both the value of electricity itself and the value of the renewable attributes of the electricity, "where appropriate justification exists." (Section 2827(h)(4)(A).)
As described in Section 3.1 above, the Commission can implement an NSC rate based on avoided costs. We will adopt an avoided cost approach that we determine reflects, as closely as possible, the incremental cost the utility avoids by receiving surplus generation from NEM customers, and complies with the mandate of Section 2827(h)(4)(A-B) that the adopted rate be just and reasonable, leave other ratepayers unaffected, and not shift costs between solar
customer-generators and other bundled service customers. We accept the suggestion of DRA, TURN and the Joint Solar Parties to base the NSC rate on the Commission-adopted MPR. We find the MPR to be reasonable for two reasons. First, the use of the MPR is consistent with our previously adopted feed-in tariff for small renewable energy facilities. In D.07-07-027 we established a feed-in tariff for small renewable energy facilities with a capacity of 1.5 MW or less, which is set at the TOD adjusted MPR. Second, as DRA and the Joint Solar Parties have indicated, the average price paid for RPS-eligible energy over the past few years has exceeded the MPR. (DRA, 6/21/10 at 10; Joint Solar Parties, 7/23/10 at 4.)
With the passage of Senate Bill 2X on March 29, 2011, the Commission would no longer be required to calculate an MPR for the RPS program. Thus, future updates to the MPR are unknown at present. If the Commission does not continue to update the MPR, the last MPR approved by the Commission will continue to serve as the basis for the NSC rate. In that event, parties may file a petition for modification of this decision to request the Commission consider using an alternate method to set NSC rates.
We accept the Joint Solar Parties' recommendation that the NSC rate be adjusted for TOD using the typical hourly profile of solar output, and we adopt the TOD factors that they propose. (Joint Solar Parties, 6/21/10 at 3.) As PG&E noted, hourly export data is not collected so the true export profile is not known. (PG&E, 7/23/10 at 6.) However, in the absence of better data, the typical production profile of fixed-axis solar panels serves as a reasonable proxy. (Joint Solar Parties, 6/21/10 at 6.)
The Joint Solar Parties propose that the net surplus generators receive payments at a fixed rate over twenty years using the twenty-year MPR for the contract start date that applies to the year the solar panels commence operation. (Joint Solar Parties, 6/21/10 at 2.) DRA and TURN support using an NSC rate based on the MPR, but they suggest that the NSC rate vary from year to year using the most recent MPR and that the same rate apply to all customers. Net surplus generators are dissimilar from independent power producers that sell electricity to utilities under long-term contracts. Independent power producers who invest in renewable energy facilities as a business depend on predictable long-term revenue streams, and their motivation for producing electricity for sale to a utility is primarily to generate revenue. In contrast, as NEM customers, net surplus generators install renewable generating facilities on their premises principally to offset part or all of their own electrical requirements, and they do not sign long-term contracts with utilities to sell excess energy at a given price. Taking these factors into consideration, we agree with TURN and DRA that net surplus generators should all receive payments based on the most recently approved NSC rate in effect at the time the true-up is calculated. In other words, net surplus generators should not receive long-term fixed NSC rates based on the date that the generator's system becomes operational.
The MPR approved in any given year is actually an array of values that varies depending on the contract length and the year that a facility commences commercial operations.22 The NSC rate should be based on the twenty-year contract price for the earliest online date listed in the most recently adopted table of MPR values in effect at the time the annual true-up is calculated. Using the 2009 MPR values as an example, the base NSC rate, before TOD adjustments are applied, is 9.674 cents per kWh.
We do not adopt the adders for avoided T&D costs and avoided line losses that the Joint Solar Parties seek to include in the NSC rate. We agree with the utilities that we should not include avoided T&D in the NSC rate because it has not yet been demonstrated that net surplus generation avoids these costs. We have no way of knowing if each of the net metering customers would be in congested areas or would always be in a situation where they do not need to purchase electricity from the utility. Therefore, it is not appropriate to include T&D benefits here. Similarly, we will not adopt an avoided line-loss adder at this time.
The MPR-based NSC rate is a bundled rate that includes the value of the renewable attributes associated with the net surplus generation. That bundled NSC rate must be disaggregated into an energy-only rate and a green premium for two reasons. First, it will take some time for the utilities to meet with the voluntary REC market organizations and work out a process for satisfactorily resolving REC ownership, as described in section 5.2. In order to expedite the initial payments under the NSC program, net surplus generation trued-up before the Commission's approval of the REC ownership verification process should be paid using the energy-only NSC rate because the net surplus generation will not count toward RPS targets until the verification process is approved. Once the REC ownership status has been established, the green premium for the initial true-up period should be paid retroactively to the REC owners whose RECs are transferred to the purchasing utility. Second, separate energy-only and green premium rates will be needed on an ongoing basis in order to pay the
energy-only rate to customer-generators who have sold the right to their RECs and to pay the green premium rate to the owners of REC associated with net surplus generation who choose to sell their RECs to the utilities purchasing the net surplus generation. We will adopt SCE's proposal to use the most recent WECC-wide average green premium as reported by the DOE. The value shown in SCE's proposal is 1.83 cents per kWh. (SCE, 6/21/10, Attachment A at A-2.) The resulting rates for SCE, SDG&E and PG&E are shown in the table below.
Net Surplus Compensation Bundled, Green Premium,
and Energy Only Rates
2009 MPR, 20-year contract, 2010 online date
Full Bundled NSC Rate
Energy-Only NSC Rate
With regard to CalPECO (formerly Sierra Pacific) and PacifiCorp, we realize these two utilities have very few customers that may qualify for NSC payments, and we agree that we should make administration of NSC as simple as possible given the unique characteristics of these two utilities with small territories in California. The record does not indicate whether CalPECO and PacifiCorp have standard TOD factors to adjust MPR. Therefore, for administrative simplicity, we direct CalPECO and PacifiCorp to each file a Tier 2 advice letter in compliance with this order adopting the NSC rate of PG&E, SCE, or SDG&E.
The other small and multi-jurisdictional utilities (SMJUs; namely Bear Valley Electric Service (BVES) and Mountain Utilities) were not parties to this proceeding but we must also make provisions for them to offer net surplus compensation to their customers. Consequently, we shall require BVES and Mountain Utilities to each file a Tier 2 advice letter adopting the NSC rate of PG&E, SCE or SDG&E or file an application describing an alternative net surplus compensation rate and a detailed explanation why a deviation from the methodology adopted in this decision is necessary for their operations.
The rates shown above should be updated when a new MPR is adopted by the Commission and/or DOE releases a new value for the average green premium in the WECC. Within 30 days of any change to the MPR or the DOE published WECC renewable energy premium, each utility shall file updated NEM tariffs with revised net surplus compensation rates by Tier 2 advice letter. BVES and Mountain Utilities may be exempt from this requirement if we approve an NSC rate for them that does not rely on the MPR.
It is important to simplify the calculation of the NSC rate and the administration of the NSC program in order to keep administrative costs reasonable relative to the value of the net surplus generation. According to PG&E, data from 2009 indicates that fewer than 10% of its NEM customers, or 2,450 customers, were net exporters of electricity and they generated a total of 5,212,073 kWhs. (PG&E, 3/15/10 at 10 and 12.) Thus, the total value of PG&E net surplus generation at the full NSC rate shown in the table above equals approximately $630,000. Data supplied by CALSEIA/EC supports the conclusion that total dollars that will be paid out for NSC is likely to be minimal. They report that in 2009, SDG&E had fewer than 1,000 customers eligible for NSC, generating on average less than 2,500 kWhs, indicating a total NSC value of less than $270,000. SCE reported fewer than 1,500 customers eligible for NSC, also generating on average less than 2,500 kWhs, yielding a total NSC value of less than $480,000. (CALSEIA/EC, 6/21/10 at 6.)
We find the Joint Solar Parties' NSC proposal is administratively simple because it relies on a value that has been updated and adopted by the Commission on a regular basis. The simplicity of this approach gives us an avoided cost NSC rate at a low administrative cost. We do not want the cost of implementing NSC to dwarf the compensation the customers receive under the program.
According to Section 2827(h)(3), customers were notified in January 2010 that they could opt to receive NSC. Therefore, the NSC rates approved through each utility's advice letter will apply to customers who chose NSC when notified in January 2010, or thereafter.
6.1. Discussion of Proposals Not Adopted
We decline to adopt other parties' proposals as set forth below.
6.1.1. Utility Proposals for Value of Energy
PG&E proposes an NSC rate based on a simple rolling average of the hourly DLAP prices from 7 a.m. to 5 p.m. over the customer's true up period. PG&E argues that this rate represents the price that a utility pays for a quantity of energy sufficient to meet its day-ahead load and the costs the utility avoids when NEM customers export excess energy between 7 a.m. and 5 p.m. We reject PG&E's proposal because it ignores the fact that net surplus generation counts toward the utilities' annual RPS targets; therefore, net surplus generation should more appropriately be compared to the cost of other sources of electricity that apply toward meeting RPS targets. We conclude that basing the NSC rate on a simple rolling average of hourly DLAP prices does not reasonably reflect the costs the utility avoids in procuring electricity from renewable sources.
Similar to PG&E's proposed electricity value, SCE's proposal involves an avoided cost based on market prices. PG&E's proposal uses DLAP prices because net surplus generation will create exports from NEM customers, which will likely offset other customers' load and result in fewer purchased kWhs of load at the DLAP price. SCE's proposal is less appropriate because the MRTU generation hub price is the price paid for additional kWhs of sales to the CAISO, and NEM customer generators do not sell directly to the CAISO. (PG&E, 3/15/10 at 4, n. 1.)
Moreover, we agree with the Joint Solar Parties and Acton that SCE's method of converting bill credits to NSC using a weighted average ratio is overly complex, results in different prices for different customers, and could result in higher administrative costs. (Joint Solar Parties, 7/23/10 at 17.) As the Joint Solar Parties point out, it is problematic that under SCE's proposed NSC ratio approach, a customer's payment is determined in part by the size of any remaining bill credit. The larger the bill credit, the larger the payout, while a customer with net surplus generation but no bill credit receives no NSC payment. In addition, SCE proposes to weight average hourly MRTU prices based on a customer load profile. SCE provides only one sentence in an attachment explaining this solar profile weighting and we find this explanation insufficient.
SDG&E and PacifiCorp both propose NSC rates based on SRAC prices paid to QFs. We prefer an avoided cost approach to valuing NSC, in line with the authority granted in the recent FERC order that allows us to differentiate avoided costs on the basis of the supply characteristics of the different technologies, i.e., the unique attributes of the excess power received from net surplus generators. (See 133 FERC ¶ 61, 059 (October 21, 2010) at ¶ 23.) Although SRAC QF pricing sounds simple and straightforward, it is not. SRAC QF rates are frequently subject to litigation and adjustment in regulatory proceedings. Plus, there are many different settlements and rates for QFs, depending on whether they are renewable or non-renewable.
We also reject the interim rate proposed by PG&E and the rate proposed by Sierra Pacific. PG&E suggests an interim NSC rate based on its system average generation rate, while Sierra Pacific proposes an NSC equal to the generation component for baseline quantities from its retail rates. PG&E acknowledges that its proposed interim rate is the generation component of retail rates and represents embedded or average, costs and not avoided or marginal costs. (PG&E, 3/15/10 at 5, n. 3.) Sierra Pacific's proposed rate is similar. Both of these rates are set in regulatory proceedings based on utility costs. We consider our approach of identifying an avoided cost to be superior. In our view, it is more appropriate to compensate net surplus generators using an avoided cost rather than an embedded cost.
6.1.2. Other Proposals for Value of Energy
We decline to adopt proposals by CALSEIA/EC and Solutions for Utilities to base NSC on retail electric rates because, in our view, this would
over-compensate NEM customers by paying them a rate above and beyond the value of electricity. As the utilities point out, costs associated with T&D infrastructure, billing, and other utility services are not avoided when a customer installs a generation system. If we set the NSC at the full retail electric rate which includes T&D, and other utility administrative and overhead costs, this would shift the collection of these costs to other ratepayers in violation of Section 2827(h)(4)(A) which requires that non-participating customers be indifferent to the NSC rate.
Further, we will not adopt the proposal by CALSEIA/EC to set the NSC rate equal to the feed-in tariff rate that will be adopted in R.08-08-009 pursuant to SB 32. AB 920 requires the Commission to set the NSC rate by January 1, 2011. Proceedings to set the SB 32 feed-in tariff rate are at a preliminary stage and it is unclear when the feed-in tariff would be available and whether it would even apply to PacifiCorp and Sierra Pacific. CALSEIA/EC fail to suggest what rate should apply in the interim, while there is no feed-in tariff rate in effect.
Moreover, we reject the adders to the feed-in tariff rate proposed by CALSEIA/EC to account for avoided emissions costs and health benefits to society. As PG&E notes, emission control costs are not avoided by the utility when NEM customers provide net surplus power. If the NSC rate included emissions adders on top of avoided energy values, PG&E would be paying twice for the same costs. Moreover, we agree with Acton, TURN and PG&E that
non-monetized benefits such as "health benefits for avoided state emissions" have not been recognized by the Commission to date and are too vague.
We will not adopt the proposal by Acton to set NSC based on RPS contract prices. We agree with SDG&E, PG&E and SCE that it is not reasonable to pay RPS contract prices when there is no long-term commitment from NEM customers to generate surplus power. In our view, ratepayers would not be indifferent if they were paying a premium contract price for non-contracted power. As SCE notes, NEM customer generators' systems are intended primarily to offset part or all of each NEM customer's own electrical requirements and are not dedicated generating systems built solely to serve a utility's load.
The proposal by the City of San Diego to equate the NSC with the price paid for utility-owned solar generating plants is also rejected.23 SCE and TURN contend that the Commission-adopted price of utility-owned solar plants is an "all-in" price for a long-term central station generating facility with a long-term contract, and it is inappropriate to compensate intermittent surplus generation at this rate. TURN adds that it is unreasonable to pay the full, levelized cost of utility-owned solar for excess NEM generation, especially when ratepayers already subsidize NEM customer-generators through California Solar Initiative (CSI) and the Self Generation Incentive Program (SGIP) incentives and by paying NEM bill credits at the full retail electric rate. We agree.
Finally, we reject the proposal by DRA to base the NSC rate on DG avoided cost calculations. While the Commission adopted a methodology to analyze DG costs and benefits in D.09-08-026, and this methodology includes DG avoided cost estimates, certain components of the methodology were not finalized in D.09-08-026, and work continues to address these components. This proceeding is not an appropriate venue to examine these debated components and settle long-standing disputes over DG avoided cost calculations.
6.1.3. Renewable Attribute Value Proposals not Adopted
We have already stated that the MPR-based NSC rate is a bundled rate that includes the value of the renewable attributes associated with the net surplus generation. We have also explained that the bundled NSC rate must be disaggregated into an energy-only rate and a renewable premium. For the interim, we agree with SCE's proposal to base the renewable premium on premiums published for the WECC by the DOE.
PG&E and SDG&E both suggest that once REC trading is in place in California, renewable attributes could be priced using the average REC price over a 12-month period.24 In the interim period prior to REC trading, SDG&E suggests adding the MPR GHG adder of 0.8 cents/kWh to the electricity portion of the NSC rate if the renewable energy that is purchased is RPS-eligible. PacifiCorp proposes an adder of one cent/kWh.
CALSEIA/EC, the Joint Solar Parties, Acton, and City of San Diego do not suggest a separate value for renewable attributes because they propose a bundled rate, based on either retail rates, feed-in tariff rates, the MPR, contract prices under RPS, or utility-owned solar prices. The bundled rate proposals include compensation for both electricity and renewable attributes. Similar to the utility proposals, the Joint Solar Parties suggest that once a REC price is established by a market, that price could be substituted for the GHG adder currently embedded in the MPR. Sierra Pacific proposes no compensation for renewable attributes because it maintains NEM customers are not RPS eligible or tracked by WREGIS.
CARE provides no estimated value for renewable attributes, although it maintains that GHG offsets in the form of RECs are an energy ancillary service that the Commission maintains authority over in regard to the price that is paid to QFs. CARE contends the implied REC price is the difference between the cost of the standard contract and the market value of a comparable brown energy product. PG&E claims CARE's comments contain incorrect statements regarding FERC jurisdiction and there is no foundation for CARE's argument that a REC or a GHG offset are similar to ancillary services.
We agree with proposals by PG&E, SDG&E and the Joint Solar Parties that once a REC market develops and there is a means to obtain public REC prices, we should use publicly-available average REC prices in California over 12-month period as our renewable premium rather than WECC region premium published by DOE. Therefore, we will reconsider the appropriate value for renewable attributes once there is a publicly-available index of California RPS-eligible REC prices. Parties may file a petition for modification of this decision when such an index emerges.
7.1. Does the customer need a bill credit to be eligible for an NSC payment?
SCE, SDG&E, and PacifiCorp maintain that to qualify for an NSC payment, an NEM customer must have a remaining bill credit as well as generation in excess of usage. According to SDG&E, if a customer has used up all its bill credits earned during the 12-month true-up period, the customer has already been compensated for all excess generation at the full retail electric rate. SCE and SDG&E contend that to provide further compensation in excess of the retail rate would amount to double payment, shifting costs to non-participating customers.
In contrast, PG&E, the Joint Solar Parties, Acton, City of San Diego, IREC, and TURN claim that NEM customers should not be required to have a remaining bill credit to receive NSC. These parties generally assert that if a customer has generated surplus power, the customer should be compensated, and that any bill credit at the end of the true-up period should be irrelevant. PG&E maintains that the eligibility for NSC is based on net generation only, and there is no mention of a bill credit requirement in the statute. Moreover, PG&E describes how bill credits can bear no relation to the amount of surplus electricity exported by an NEM customer. PG&E asserts that if bill credits are required for or linked to NSC, senseless and unfair results can ensue, with some customers receiving well below avoided costs and others receiving tens or hundreds of dollars per kWh of net surplus. (PG&E, 3/15/10 at 8.) TURN and DRA both comment that NSC payments should be reduced by any bill debits owed on the true-up date.
Another variation on the issue is raised by CALSEIA/EC. They contend that if an NEM customer has a bill credit but no net surplus generation, the customer should still receive an NSC payment. According to CALSEIA/EC, this can occur when an NEM customer on a TOU rate provides excess generation during hours of peak electricity demand when rates are high, but uses most of its electricity off-peak when rates are lower. As a result, the customer may have a bill credit even though it did not generate excess energy over a 12-month period. The Joint Solar Parties and TURN argue that NEM customers with a bill credit but no net surplus should not be compensated.
Upon review of AB 920, we agree with PG&E that the language in the statute is straightforward and that customers who generate more kWhs than they use in their 12-month true-up period may choose to receive net surplus compensation. We will not add a secondary requirement, which does not appear in the statute, that customers must also have a bill credit to be eligible for net surplus compensation. Moreover, we agree with TURN and DRA that any payment for NSC should be reduced by any amount the customer owes to the utility. We disagree with the proposal by CALSEIA/EC that customers with a bill credit and no net surplus generation should receive further compensation. Again, we return to the plain language of the statute that requires compensation when customers are net generators. If a customer has not generated excess kWhs, the customer is not eligible for NSC.
7.2. Rollover of Excess kWh
Section 2827(h)(3) allows eligible customer-generators to elect whether to receive net surplus compensation for any net surplus electricity generated during the prior 12-month period, or whether to apply, or "rollover," the net surplus electricity as a credit for kWhs subsequently supplied.25 Several parties raise conflicting views on how to handle NSC if the NEM customer opts to rollover the net surplus as a credit against future usage.
IREC maintains that because AB 920 creates two options for NEM customers, either compensation or a bill credit, there can be two NSC rates -- one that applies if a customer chooses immediate compensation, and a separate rate if a customer elects to rollover excess generation. In other words, if a customer chooses to rollover net surplus as a credit against future usage, IREC contends the rate used for future credits is not subject to the requirement in Section 2827(h)(4)(A) that other ratepayers be left unaffected. Thus, IREC claims that any rollover of net surplus generation should offset the full retail electric rate of subsequent usage.
PG&E and SDG&E argue that IREC's reading of AB 920 is not credible and defies statutory construction because the statute makes clear that NSC implementation options should leave other ratepayers unaffected, whether a customer chooses an immediate cash payment or a credit against future usage.
We agree with PG&E and SDG&E. The value that customers receive for net surplus generation should be the same whether the customer chooses immediate compensation or opts to rollover net surplus generation against future usage. The value of net surplus generation should be converted to a monetary credit before being carried forward. If net surplus generation were carried forward as IREC suggests, it could offset later usage at different and potentially higher retail rates. We have already found in Section 5.1.3 that providing NSC payments at the full retail electric rate shifts costs to other customers. We now add to that finding that providing NSC rollover credits at future retail electric rates, which might be higher than the rates in effect at the time the surplus was generated, could shift costs to future customers. Additionally, IREC's proposal could be difficult to implement. Currently, SDG&E, PG&E and SCE convert kWh to dollars on a monthly basis as part of NEM and changing this would cause administrative costs and customer confusion.
We find it more reasonable to adopt the recommendation of PG&E, SCE and the Joint Solar Parties that net surplus generation should be valued at the conclusion of the relevant true-up period at the same price whether a check is mailed to the customer or a credit is applied to the bill against subsequent usage. In other words, if customers choose to rollover excess kWhs, the dollar amount of any net surplus compensation will be applied to the customer's account directly rather than drafting a separate check. Once the excess kWhs have been valued in dollars, the kWh values in all time periods should be reset to zero and the cycle starts anew. We agree with the proposal by several parties that the utilities should allow NEM customers to maintain such NSC bill credits indefinitely. In addition, we will allow customers to switch from compensation to rollover, or vice versa, on an annual basis.
Sierra Pacific, which has very few NEM customers, requests unique treatment. It proposes the same concept that IREC endorsed, that is, to allow banking of surplus electricity in the form of kilowatt hours, which would be treated as a credit and used to offset kilowatt hours subsequently supplied by Sierra Pacific. Although Sierra Pacific has only a handful of NEM customers, we see no reason for unique treatment. Sierra Pacific should value excess kWhs annually and either mail a payment to the customer or apply that credit to future usage.
7.3. Minimum Payment Amount
PG&E recommends a one dollar minimum payment amount for a customer to receive a check for NSC. The Joint Solar Parties and CALSEIA/EC agree this is reasonable unless the customer is closing the account. Sierra Pacific suggests a higher minimum threshold for its NSC payments based on its unique characteristics. Sierra Pacific proposes that if customer's net surplus is valued at less than $25 after 12 months, the valuation of the net surplus should be applied as credit for kWh subsequently supplied.
We will adopt a requirement that customers need a one dollar minimum NSC payment to receive a check from the utility. We further agree that for Sierra Pacific and PacifiCorp, this minimum payment amount should be $25 to minimize the administrative costs on these smaller utilities with few NEM customers.
7.4. System Sizing Limits
The definition of an eligible customer-generator in Section 2827(b)(4) includes the statement that the system "is intended primarily to offset part or all of the customer's own electrical requirements."
The utilities maintain that the NSC scheme established by AB 920 is intended to address random, modest, inadvertent net exports and that NEM customers must adhere to this existing NEM system sizing limit, which has been a long-standing prerequisite for NEM participation, in order to qualify for NSC payments. The utilities contend that since the statute for net surplus compensation retains the system sizing limit language, customers cannot oversize their solar or wind electrical generating facilities to create additional revenue. Moreover, the utilities note that other compensation mechanisms exist for customers who want to generate electricity to sell to the utility, such as
feed-in tariffs. CALSEIA/EC agree with the utilities, suggesting that customers who oversize their systems would not qualify for NEM, and therefore would be ineligible for NSC.
In contrast to the utility position, the Joint Solar Parties and Acton read the statute as not limiting the size of a customer's system except to less than 1 MW. DRA suggests the impact of AB 920 on current system sizing limits should be examined in R.10-05-004, where the Commission could consider exceptions to allow systems sized above historic demand.
We agree with the utilities that nothing in AB 920 alters the existing NEM system sizing language and that to be eligible for NSC, a system must meet the definition of an eligible customer-generator within Section 2827(b)(4), including that it be intended primarily to offset part or all of the customer's own electrical requirements. Systems that are sized larger than the customer's electrical requirements would not be eligible for NEM and therefore, are not eligible for NSC either.
7.5. Should customers repay CSI or SGIP incentives to receive NSC?
Sierra Pacific and PacifiCorp recommend that the Commission require repayment of CSI or SGIP incentives as a condition for receiving NSC. Most other parties assert that customers should not be required to repay any incentives they received from CSI or SGIP in order to receive NSC. Several parties cite to Section 2827(c)(1), which states:
Eligibility for [NEM] does not limit an eligible
customer-generator's eligibility for any other rebate, incentive, or credit provided by the electric utility, or pursuant to any governmental program, including rebates and incentives provided pursuant to the [CSI].
We agree with the majority of the parties that it would be inconsistent with Section 2827(c)(1) to require repayment of CSI or SGIP incentives. In addition, even without this statutory limitation, it would undoubtedly create administrative and billing complications to attempt to collect repayment of prior CSI or SGIP incentives from customers.
7.6. Are Community Choice Aggregation, Direct Access, and other customers eligible to receive NSC?
Several parties question whether customers of Community Choice Aggregators (CCAs) and direct access customers of energy service providers (ESPs) are eligible to receive NSC payments. PG&E, CALSEIA/EC, IREC, and the Joint Solar Parties generally propose that the Commission require CCAs and ESPs to offer NSC to their customers who participate in NEM and are net surplus generators. PG&E further states that customers who receive service from ESPs and CCAs should not receive NSC payments because PG&E is not their generation supplier. The Joint Solar Parties clarify that NEM customers should be compensated by the relevant CCA or ESP for the generation component of the NSC. PG&E proposes that additional customer groups, namely wind energy
co-metering customers (i.e., wind generators from 50 kW to 1 MW), multiple tariff treatment customers, and virtual net metering (VNM) customers under the CSI Multifamily Affordable Solar Housing Program also be eligible to receive NSC.
SDG&E opposes requiring CCAs and ESPs to offer NSC, although SDG&E suggests these entities may choose to offer NSC. Sierra Pacific contends that according to Section 2827(b)(4), eligible customer-generators must be a "customer of an electric utility" to qualify for NSC.
First, we will not require ESPs to offer NSC because they do not match the definition of electric utility in the statute. Section 2827(b)(3) defines an electric utility as "an electrical corporation,...an electrical cooperative, or any other entity, except an electric service provider, that offers electrical service." (Emphasis added.)
Second, we will not require CCAs to offer NSC to their customers at this time because CCAs did not receive adequate notice of this proceeding concerning implementation of the NSC program. CCAs do not appear to have been included on the service list for this rulemaking. CCAs may choose to offer NSC to their customers and the Commission may, at a later date, consider requiring CCAs to provide NSC. CCAs that choose to offer NSC will need to coordinate customer enrollment with the utilities to ensure that no net surplus generator benefits from more than one NSC program for the same generation.
Finally, we will allow PG&E and the other utilities to offer NSC to any NEM customer, including wind energy co-metering customers, VNM customers, and multiple tariff treatment customers. PG&E's compliance filing containing its revised NEM tariffs should address how NSC will apply to these various customer classes.
7.7. Administrative Costs
The utilities propose that their costs to implement and administer NSC should be absorbed by all customers rather than applying an administrative fee on NEM customers alone. PG&E contends that the costs of implementing the NSC program could overwhelm much of the value of the program to eligible net generators. According to PG&E, in 2009, less than 10% of its NEM customers, or 2450 customers, had a credit at the time of their true-up and were net exporters of electricity, and of those net exporters, over 40% had net exports of 100 kWh or less. (PG&E, 3/15/10 at 10-12.) PG&E claims that the cost of tracking these customers, notifying them of their options, cutting checks, and other administrative duties could be larger than their compensation.
The Joint Solar Parties and City of San Diego agree with PG&E that the costs to administer the NSC program should be absorbed by all customers.
We agree that payments to individual net surplus generators are likely to be small. If the utilities assessed a fee on customers to participate in this program, the fee could be larger than any NSC payments. We accept PG&E's recommendation that the administrative costs of NSC, which we expect to be minimal, be absorbed by all customers. This is similar to how costs of implementing NEM tariffs and other alternative billing arrangements are allocated widely to all customer classes as billing-related costs in utility general rate cases. In the event administrative costs are larger than anticipated, we may reconsider this allocation of administrative costs.
7.8. NEM Tariffs
Most parties agree that the details of the NSC program, including the NSC rate and details concerning NSC payments, should be incorporated into the utilities' existing NEM tariffs. We agree and we will require the utilities to include revised NEM tariffs incorporating the NSC rates, terms, and conditions set forth in this decision in the advice letter they each submit with their specific NSC rate calculations in compliance with this decision.
The alternate proposed decision of Commissioner Peevey in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission's Rules of Practice and Procedure. Comments were filed on _____________, and reply comments were filed on _________________ by ________________________.
Nancy E. Ryan was the original assigned Commissioner and Dorothy J. Duda is the assigned ALJ in this proceeding. The case was reassigned to Michael R. Peevey as assigned Commissioner in January 2011.
1. Section 2827 requires the Commission to establish a program to compensate NEM customers for electricity produced in excess of on-site load at the end of a 12-month true-up period, i.e., "net-surplus generation."
2. Under Section 2827, customers may opt to receive either a payment for
net-surplus generation or to roll a credit for that generation into the next 12-month period.
3. Section 2827 requires that any compensation for net surplus electricity leave other ratepayers unaffected and not result in a shifting of costs between solar customer-generators and other bundled service customers.
4. According to FERC, a transfer of net surplus energy by a net metering customer to a utility constitutes a wholesale transaction that must comply with either the FPA or PURPA.
5. FERC has found that wind and solar generating facilities of 1 MW can be considered QFs without filing for certification with FERC.
6. NEM customers eligible for NSC must use a solar or wind generating facility of not more than 1 MW.
7. Rule 21 governs QF interconnections.
8. According to Section 2827, net surplus compensation may include either or both the value of electricity and the value of the renewable attributes of the electricity.
9. The amount of net surplus generation that is likely to be compensated is quite small compared to California's total electricity load.
10. Within the 12-month true-up period, customers will continue to receive a credit at the full retail electric rate up to the amount that offsets their usage, and the NSC rate will only apply to generation in excess of that amount.
11. Sierra Pacific and PacifiCorp have few customers that may qualify for NSC payments.
12. In recent years, the average price of energy procured by the utilities in their solicitations for renewable energy has exceeded the MPR.
13. Data on the time of day that net surplus generation is delivered to the grid are not currently available.
14. Section 399.12 defines a REC as "a certificate of proof, issued through the accounting system established by the [CEC] pursuant to Section 399.13" and Section 399.13 gives the CEC the authority to certify eligible renewable energy resources.
15. According to Section 2827(h)(5)(A), if a utility purchases net surplus electricity, any RECs associated with that net surplus electricity shall belong to the utility.
16. To qualify for RPS compliance, renewable energy generators must usually be certified as eligible by the CEC, and the REC must be tracked and verified in WREGIS.
17. At this time, the CEC has not certified DG systems as eligible for RPS compliance, except DG systems under AB 1969 tariffs.
18. To the extent two statutes are irreconcilable, when a subsequently enacted specific statute directly conflicts with an earlier more general provision, the subsequent legislation affects a limited repeal of the former statute.
19. It is unclear if WREGIS can track and verify RECs that would be split between a utility and a customer.
20. RECs for RPS compliance are accounted for in 1 MWh increments and it is unclear if net surplus generation from multiple small facilities can be aggregated.
21. REC trading was only recently authorized by the Commission, and a publicly available index of California RPS-eligible RECs does not currently exist.
22. Section 2827 does not require NEM customers to have a bill credit to be eligible for net surplus compensation.
23. Section 2827 states that an eligible customer-generator's system is intended to primarily offset part or all of the customer's own electrical requirements.
24. NSC payments to individual net surplus generators are likely to be small and any administrative fee assessed on customers for the NSC program could be larger than the NSC payment.
25. ESPs are not electric utilities under Section 2827.
1. The Commission may adopt an NSC rate that does not exceed avoided costs consistent with PURPA.
2. NEM customers can be considered QFs, exempt from FERC certification.
3. Tariff Rule 21 should continue to govern interconnection between utilities and NEM customers who self-certify to the utility as QFs.
4. An avoided cost approach to valuing net surplus compensation reflects as closely as possible the costs the utility avoids by receiving surplus generation from NEM customers while leaving other ratepayers unaffected and not shifting costs between customer-generators and other customers.
5. Use of an avoided cost approach to value net surplus compensation allows NEM customers to be compensated for both the value of electricity and the value of renewable attributes.
6. Other ratepayers are unaffected if the utility compensates net surplus generation at avoided cost.
7. The MPR is a reasonable and efficient source for an avoided cost value for renewable electricity as required by Section 2827.
8. In the absence of time of delivery data for net surplus generation, the generation profile of a typical fixed-axis solar panel serves as a reasonable proxy.
9. According to Section 2827(h)(3), small and multi-jurisdictional
investor-owned electric utilities operating in California must offer net surplus compensation to their customers.
10. An NSC rate based on the full retail electric rate would provide compensation above the value of electricity and shift costs to other ratepayers.
11. Net surplus generation purchased by the utility may be counted toward RPS procurement targets, even without CEC certification and WREGIS tracking, but only after the Commission approves a process to ascertain the REC ownership status of the facilities providing net surplus generation.
12. Until an index of California RPS-eligible REC prices emerges, the use of the Department of Energy's annual survey of average WECC-wide renewable energy premiums should serve as the source of the renewable attribute value embedded in the NSC rate.
13. Payments for NSC should be reduced by any amount the customer owes to the utility.
14. If a customer has not generated excess kWhs, the customer is not eligible for NSC.
15. The value a customer receives for net surplus generation should be the same whether the customer chooses immediate compensation or opts to apply net surplus generation to offset future usage. Therefore, the value of net surplus generation should be converted to a monetary credit before being carried forward.
16. NEM customers may maintain NSC bill credits indefinitely and may switch from NSC payment to rollover, or vice versa, on an annual basis.
17. NEM customers should have a one dollar minimum NSC payment to receive a check from the utility, except NEM customers of Sierra Pacific and PacifiCorp should have a $25 minimum NSC payment to receive a check.
18. Systems sized larger than the NEM customer's electrical requirements would not be eligible for NEM and, therefore, are not eligible for NSC.
19. ESPs should not be required to offer NSC.
20. The Commission should not require CCAs to offer NSC to their customers at this time, although CCAs may choose to offer NSC.
IT IS ORDERED that:
1. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each base their net surplus compensation rate on the most recently Commission-adopted Market Price Referent, which is the twenty-year contract price for the earliest online date listed for the Market Price Referent. This Market Price Referent rate shall be adjusted for time of delivery factors and the most recent Western Electricity Coordinating Council renewable energy premium reported by the United States Department of Energy, as shown in Table 3 of this decision.
2. Within 30 days of the effective date of this decision, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each file a Tier 3 advice letter revising their net energy metering tariffs to include net surplus electricity compensation pursuant to Public Utilities Code 2827 and the net surplus compensation rate as set forth in Ordering Paragraph 1. The net surplus compensation rate for each utility shall take effect upon Commission approval of that utility's advice letter and may be used to compensate customers who chose net surplus compensation when notified in January 2010 or thereafter.
3. Within 30 days of the effective date of this decision, California Pacific Electric Company and PacifiCorp d.b.a. Pacific Power shall each file a Tier 3 advice letter in compliance with this order to: a) revise their net energy metering tariffs to incorporate the net surplus compensation rates, terms, and conditions set forth in this decision; and b) notify the Commission whether they will use the net surplus compensation rate adopted for Pacific Gas and Electric Company, Southern California Edison Company, or San Diego Gas & Electric Company.
4. Within 60 days of the effective date of this decision, small and
multi-jurisdictional investor-owned electric utilities operating in California, other than California Pacific Electric Company and PacifiCorp, shall either file a Tier 2 advice letter to adopt the net surplus compensation rate of Pacific Gas and Electric Company, Southern California Edison Company, or San Diego Gas & Electric Company, or file an application describing an alternative net surplus compensation rate and a detailed explanation why a deviation from the methodology adopted in this decision is necessary for their operations.
5. Within 30 days of either the effective date of the Commission adopting an updated Market Price Referent or the publication by the United States Department of Energy of an updated average renewable energy premium for the Western Electricity Coordinating Council region, Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, California Pacific Electric Company and PacifiCorp shall each file Tier 2 advice letters revising their net energy metering tariffs to incorporate the updated Market Price Referent and/or renewable energy premium values.
6. Until the Commission approves a process for establishing the renewable energy credit ownership status of net surplus generators, net surplus generation shall not count toward the utilities' renewable portfolio standard targets, and the utilities shall compensate net surplus generators using the energy-only net surplus compensation rates shown in Table 3 of this decision. The utilities should pay net surplus generators at the energy-only net surplus compensation rate as soon as the advice letter in Ordering Paragraph 2 is approved.
7. As soon as practicable after the issuance of this decision, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall confer with developers of distributed generation solar energy projects, renewable energy credit aggregators, voluntary renewable energy credit certifiers, and Energy Division staff to develop a common process by which Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company will determine the renewable energy credit ownership status of net surplus generators. The small and
multi-jurisdictional investor-owned electric utilities operating in California may elect to participate in this process.
8. Within 120 days of the effective date of this decision, each investor-owned electric utility in California shall file a Tier 3 advice letter that proposes a process for verifying the renewable energy credit ownership status of the net surplus generators in its territory and any revision to its net energy metering tariffs necessary to effect the proposed process. The proposed processes of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall be substantially the same. Due to the significantly smaller numbers of net surplus generators in their territories, the small and multi-jurisdictional investor-owned electric utilities operating in California may propose processes for verifying the renewable energy credit ownership status of the net surplus generators in their territories that differ from the process proposed by Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company.
9. Within 30 days of Commission approval of an investor-owned electric utility's advice letter described in ordering paragraph 8, the net surplus generation of net surplus generators who have retained ownership of their renewable energy credits and who transfer their renewable energy credits to the investor-owned electric utility shall count toward the investor-owned electric utility's renewable portfolio standard targets and the investor-owned electric utility shall use the full, bundled net surplus compensation rate, as shown in Table 3 of this decision, to calculate their net surplus compensation payments.
10. The renewable energy credits of net surplus generators who have retained ownership of their renewable energy credits and whose generation facilities are not registered in either the Western Renewable Energy Generation Information System, or any other voluntary renewable energy credit tracking system, will be deemed to be transferred to the investor-owned electric utility purchasing the net surplus generation.
11. The renewable energy credits of net surplus generators who have retained ownership of their renewable energy credits and whose generation facilities are registered in either the Western Renewable Energy Generation Information System, or any other voluntary renewable energy credit tracking system, must explicitly transfer their renewable energy credits to the
investor-owned electric utility purchasing their net surplus generation for the net surplus generation to count toward the purchasing investor-owned electric utility's renewable portfolio standard targets and for the net surplus generator to receive payment at the full, bundled net surplus compensation rate. Net surplus generators who do not transfer their renewable energy credits to the purchasing investor-owned electric utility shall be compensated at the energy-only net surplus compensation rate shown in Table 3.
12. A third party who owns the renewable energy credits associated with a net surplus generator's generation facility must register the generation facility with the Western Renewable Energy Generation Information System or a credible voluntary renewable energy credit certifying entity in order to receive compensation under the net surplus compensation program. Sales of the unbundled renewable energy credits associated with net surplus generation shall be compensated at the renewable energy premium rate identified in the purchasing investor-owned electric utility's net energy metering tariff.
13. With respect to renewable portfolio standard targets and the renewable energy premium, partial megawatt-hours of net surplus generation that remain after all full megawatt-hours of net surplus generation have been accounted for shall be rolled over to the next true-up period as shown in Table 2 of this decision.
14. Within 30 days of Commission approval of an investor-owned electric utility's advice letter described in ordering paragraph 8, the investor-owned electric utility shall count net surplus generation toward the investor-owned electric utility's renewable portfolio standard targets and compensate net surplus generators and the owners of the associated renewable energy credits in a manner consistent with ordering paragraphs 10, 11, 12 and 13. The
investor-owned electric utility shall retroactively count net surplus generation trued-up prior to Commission approval of the investor-owned electric utility's advice letter described in ordering paragraph 8, toward the investor-owned electric utility's renewable portfolio standard targets, and compensate the owners of the renewable energy credits associated with that net surplus generation using the renewable energy premium as shown in Table 3 of this decision in a manner consistent with ordering paragraphs 10, 11, 12 and 13.
15. Customers opting for net surplus compensation must notify the utility at the time they elect to receive net surplus compensation that they are a qualifying facility exempt from certification filing at the Federal Energy Regulatory Commission.
16. If a customer chooses to rollover excess kilowatt hours of net surplus generation, the dollar amount of any net surplus compensation must be applied to the customer's account directly rather than drafting a separate check. Once the excess kilowatt hours have been valued in dollars, the kilowatt hour values in all time periods should be reset to zero.
17. An investor-owned electric utility with a community choice aggregator operating in its service territory that offers net surplus compensation must coordinate customer enrollment to ensure that the same kilowatt-hours of net surplus generation are not purchased by both the investor-owned electric utility and the community choice aggregator.
18. Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, Sierra Pacific and PacifiCorp may offer net surplus compensation to any net energy metering customer, including wind energy co-metering customers, virtual net metering customers, and multiple tariff treatment customers.
19. This decision shall be served on Bear Valley Electric Service and Mountain Utilities, Inc.
20. Applications (A.) 10-03-001, A.10-03-010, A.10-03-012, A.10-03-013, and A.10-03-017 are closed.
This order is effective today.
Dated , at San Francisco, California.
1 Stats. 2009, Ch. 376.
2 Unless otherwise specified, all further section references are to the California Public Utilities Code.
3 All dates are 2010 unless otherwise noted.
4 Sierra Pacific is now known as California Pacific Electric Company (CalPECO). We will continue to refer to Sierra Pacific as all filings in this proceeding were made with that name, however any orders from this decision will apply to and refer to CalPECO.
5 CARE responded to the applications of SDG&E and PacifiCorp and protested the applications of Sierra Pacific, PG&E and SCE.
6 16 U.S.C. § 824(b)(1).
7 FERC Order 2003-A, 106 FERC ¶ 61,220 (2004) at ¶ 747 (footnotes omitted) (FERC Order 2003-A).
8 PURPA is codified generally at 16 U.S.C. § § 2601, et seq. and elsewhere in the U.S.C.
9 Section 2827(h)(4)(A).
10 Sections 2827(h)(4)(A)(i) and (ii).
11 Section 2827(h)(4)(B).
12 MidAmerican, 94 FERC P 61,340 at 62,262-63 (2001) (MidAmerican) and Sun Edison LLC, 129 FERC P61, 146 (2009) at ¶ 18 (SunEdison) ("Where there is no net sale over the billing period, the Commission has not viewed its jurisdiction as being implicated; that is, the Commission does not assert jurisdiction when the end-use customer that is also the owner of the generator receives a credit against its retail power purchases from the selling utility. [citing to MidAmerican].")
13 See, e.g., both MidAmerican and SunEdison at ¶ 18 ("Only if the end-use customer participating in the net metering program produces more energy than it needs over the applicable billing period, and thus is considered to have made a net sale of energy to a utility over the applicable billing period, has the Commission asserted jurisdiction.")
14 The "E3 avoided cost model" is named after Energy and Environmental Economics, the consultants that developed it, and was adopted in D.05-04-024, updated in D.06-06-063, and is described in D.09-08-026.
15 Joint Solar Parties, 6/21/10, Tables 1 and 2 at 3-4.
16 Stats 2006, Ch. 731.
17 Stats. 2009, Ch. 328.
18 It was difficult to discern CARE's positions from its comments and in general, its comments provided little assistance in reaching the conclusions in this decision.
19 The RPS Eligibility Guidebook (3d ed., December 2007) (available at: http://www.energy.ca.gov/2007publications/CEC-300-2007-006/CEC-300-2007-006-ED3-CMF.PDF) explains that:
The Energy Commission will not certify distributed generation PV and other forms of customer-sited renewable energy into the RPS at this time, with the following exception.
The Energy Commission will certify facilities that would have been considered distributed generation facilities except that they are participating in a standard contract/tariff executed pursuant to Public Utilities Code § 399.20, as implemented through the CPUC Decision 07-07-027 (R.06.05.027), executed pursuant to a comparable standard contract/tariff approved by a local publicly owned electric utility. . ., or if the facility is owned by a utility and meets other requirements, to become certified as RPS-eligible . . . .
The Energy Commission will not certify distributed generation facilities as RPS-eligible unless the CPUC authorizes tradable RECs to be applied toward the RPS. (RPS Eligibility Guidebook at 18.)
20 As a practical matter, the quantity of NSC generation available to be considered towards the RPS program goals is de minimus compared to the utility RPS targets. For example, in 2009, the RPS procurement target for PG&E was 11,623 GWh (see PUC RPS Quarterly Report to Legislature, 2010 Quarter 2," Table 1 at 4), while PG&E reports its excess generation from NEM customers in 2009 was 5,212,073 kWh (5.2 GWh), or approximately 0.04% of the annual RPS target.
21 For the sake of simplicity, this example assumes that the customer's true-up period is identical to the calendar year.
22 For example, see the table of 2009 MPR values at: http://docs.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/111386.htm.
23 See D.09-06-049 (SCE), D.10-04-052 (PG&E), and D.10-09-016 (SDG&E) where the Commission adopted prices for utility-owner solar plants.
24 There is currently no functionality in WREGIS to post a public REC price.
25 Section 2827(h)(3) states that if an eligible customer-generator does not affirmatively elect service pursuant to net surplus electricity compensation, the electric utility shall retain any excess kWhs generated during the prior 12 month period and the customer shall not be owed any compensation.